Methane Emission Standards for Crude Oil and Natural Gas Facilities - - PowerPoint PPT Presentation

Methane Emission Standards for Crude Oil and Natural Gas Facilities

February 2018

 Background  Regulation Requirements and Impacts  Implementation

Overview

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Background

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 Climate Change Scoping Plans identify oil & gas sector as large source of Greenhouse Gas (GHG) emissions.

 Combustion CO2 covered by Cap and Trade  Methane covered by this regulation

 Short-Lived Climate Pollutant (SLCP) Strategy includes a target of 40-45 percent reduction in methane from oil & gas sector as a whole by 2025.  Recent, separate legislation addressing well stimulation and underground storage monitoring.

Policy Drivers

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California 2013 Methane Emission Sources

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Agriculture 58% Landfills 20% Oil & Gas Extraction and Storage 4% Pipelines 9% Industrial & Miscellaneous 5% Wastewater 4%

 Third largest oil producer, 15th largest natural gas producer  Most natural gas is associated gas in California  Oil fields generally old, with enhanced recovery:

 Thermal, well stimulation

 Around 300 producers impacted by regulation

California’s Oil & Gas Operations

Dry Natural Gas (~1,700 wells) Crude Oil & Associated Gas (~68,000 wells)

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ARB and District Responsibilities

 ARB primarily responsible for mobile sources, fuels, and GHGs.  35 Local Air Districts responsible for stationary sources.  ARB’s responsibility can include stationary sources when Toxic Air Contaminants (TACs) or GHGs involved.

Other Regulations

 Districts regulating oil & gas for Volatile Organic Compounds (VOCs) for decades; exempt methane.

 ARB’s regulation covers leaking equipment not already covered by air district rules.

 Public Utilities Commission developed best practices to be consistent with ARB’s regulation.  ARB regulation covers new and existing sources, and is generally more stringent and broader than federal requirements.

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Regulation Requirements and Impacts

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 The regulation addresses fugitive and vented emissions of methane from both new and existing

• il and gas facilities.

 The covered facilities include:

• Oil and Gas Production, Processing, and Storage
• Gathering and Boosting Stations
• Natural Gas Underground Storage
• Compressor Stations

Applicability

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Regulation Standards

Separator and Tank Systems

 Applies to systems at all regulated facilities.  Requires flash testing to determine annual methane emissions.  Requires systems with annual emissions above 10 metric tons (MT) methane to install vapor collection.  Exemptions for low throughput systems and small gauge tanks.

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Regulation Standards

Circulation Tanks

 Tanks used as part of a well stimulation treatment.  Operators institute a Best Practices Management Plan, followed by a control equipment technical assessment.  If technical assessment proves

• ut, tanks controlled for

emissions by January 1, 2020.

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Regulation Standards

Leak Detection & Repair (LDAR)

 Requires daily inspections and quarterly testing to check components for leaks.  Builds on current requirements by many districts to control VOCs.  Regulation will extend testing to methane at natural gas facilities.  Optical Gas Imaging for screening, but US EPA Method 21 for enforcement.

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Regulation Standards

Underground Gas Storage

 Monitoring program designed for the early detection of leaks:

• Ambient air monitoring
• Daily or continuous monitoring at

injection/withdrawal wells.

• Incorporates recent legislative

requirements.  Operators submit monitoring plans to ARB for approval.

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Regulation Standards

Natural Gas Compressors

 Emission standards for

reciprocating compressor rod packings and centrifugal compressor wet seals.

 Requires either (1) replacement

• f high-emitting rod packing or

wet seal, or (2) collection of leaking gas.

 All compressors subject to LDAR.

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Pneumatic Devices & Pumps

 Continuous to no-bleed:

• Air or electricity to operate; or,
• Controlled with a vapor collection

system

Other Measuring and Reporting Requirements

Regulation Standards

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GHG Emission Reductions & Costs

 Overall estimated annualized cost, with natural gas savings, of $27,300,000  Estimated continuing reductions of more than 1.4 million MT of CO2 equivalent per year, using a 20 year Global Warming Potential for methane.  Estimated overall cost-effectiveness of $19 per MT of CO2 equivalent reduced.

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Emission Reduction Co-Benefits

 Over 3,600 tons per year (TPY) of VOC reductions statewide.  Over 100 TPY of reductions statewide of Toxic Air Contaminants, such as Benzene, Toluene, Ethyl- Benzene, and Xylenes.  Neutral statewide Oxides of Nitrogen (NOx) impact.

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Implementation

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Implementation Dates

 January 1, 2018:

• Flash testing
• LDAR inspections
• Natural gas storage monitoring plans
• Registration and permitting

 January 1, 2019:

• Vapor collection on separator & tank systems
• Pneumatic devices and compressor seal change-outs
• Circulation tank technology assessment

 January 1, 2020:

• Circulation tank vapor collection, pending technology

assessment

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 Regulation allows both ARB and the districts to implement; district implementation is preferred.  ARB and districts developed a model Memorandum

• f Agreement (MOA) to specify roles and

responsibilities.

• Coordinate enforcement, and support information and

data sharing.

• MOAs may be tailored for specific district needs.

Implementation

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 About half of the MOAs have been signed; rest are in progress.  For most districts, CARB handling one-time facility and equipment reporting; districts handling “on the ground” enforcement.  Will review data being reported under program and monitor program implementation.  Will periodically update Board on status and propose adjustments as necessary.

Implementation

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 Jim Nyarady, PE  jim.nyarady@arb.ca.gov  916-322-8273  https://www.arb.ca.gov/cc/oil-gas/oil-gas.htm

Questions?

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